Method for providing multiple fractures in a formation

ABSTRACT

The invention includes providing a propped hydraulic fractures in a subterranean formation including the steps of: injecting a fracturing fluid into the subterranean formation at a pressure sufficient to initiate and propagate at least one hydraulic fracture wherein the fracturing fluid comprises a proppant; when the at least one hydraulic fracture has reached a target size, adding to the fracturing fluid a predetermined amount of a diverter material wherein the diverter material comprises material having a specified size distribution, and comprising a material that degrades at conditions of the subterranean formation, the diverter material effective to essentially block flow of fracturing fluid into the at least one fracture; and continuing to inject fracturing fluid at a pressure effective to initiate at least one additional fracture within the subterranean formation.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. provisional patent application 61/941,583, filed on Feb. 19, 2014, the disclosure of which is incorporated herein by reference.

BACKGROUND TO THE INVENTION

Technology for hydraulic fracturing of formations has advanced rapidly in recent years and has enabled economic development of hydrocarbon resources previously considered to not be economically producible. Typically, long horizontal wells are provided in a target formation and fractures are provided every two hundred to five hundred feet along the length of the horizontal wellbore. Fractures are often provided by methods such as those suggested in U.S. Pat. Nos. 7,775,287 and 7,703,525 or US patent application publication US2011/0209868. These methods include injection of viscous fluids into the formation at such high pressures and rates that the reservoir rock fails and forms a plane, typically vertical (depending on the direction of minimum stress). Proppant material such as sand, ceramic beads, or other material may be injected in a later portion of the fracturing fluid to hold the fracture open after pressure on the fracturing fluid is decreased.

Either cased or uncased wellbores may be fractured, but typically wellbores within target formations are cased, the casings cemented, and then the cemented casings are perforated at predetermined intervals along the length of the wellbore.

In carbonate formations, the fracturing fluids may contain acids or acid precursors that react with carbonates to alter the shape of the rock at the surface of the fracture so that after pressure on the fracturing fluid is released, and the fracture closes, the faces of the rock no longer match. Flow paths for fluids to traverse from along the surface of the fracture to the wellbore are therefore provided.

Tools are available for isolating sections of a horizontal wellbore for fracturing perforations within that isolated segment. A further improvement has been to isolate multiple perforations, and attempt to perform multiple fractures at the same time, thus reducing rig time needed to relocate packers and set up for pumping fracturing fluids. But provision of multiple fractures from a single isolated segment of a wellbore can be problematic because a fracture will initiate at the weakest point within the isolated segment, and because fracture propagation requires less pressure than fracture initiation pressure, subsequent fractures will not initiate until the first fracture is very large, The initial large fracture will increase the stress on the formation, and therefore each subsequent fracture will be smaller and less effective than previous fractures.

U.S. Pat. No. 7,644,761 suggests a method where slugs of proppant are injected in an acid fracturing fluid so that existing fractures may be plugged, permitting pressure within the wellbore to increase to above a fracture initiation pressure and thereby initiation of a second or subsequent fracture. The proppant may be a combination suggested in U.S. Pat. No. 7,004,255, which is a combination of two or three different sizes so that the ultimate void volume of the proppant may be as low as less that seventeen percent.

It is also suggested in U.S. Pat. No. 7,644,761 that the proppant could include degradable fibers as suggested in U.S. Pat. No. 7,275,596. It is suggested that the fibers degrade at formation temperatures in a time between about four hours and one hundred days leaving a more porous screen at each fracture. U.S. Pat. No. 7,275,596 suggests a method for minimizing the amount of metal crosslinked viscosifier necessary for treating a wellbore with proppant or gravel is given. The method includes using fibers to aid in transporting, suspending and placing proppant or gravel in viscous carrier fluids otherwise having insufficient viscosity to prevent particulate settling. Fibers are suggested that have properties optimized for proppant transport but degrade after the treatment into degradation products that do not precipitate in the presence of ions in the water such as calcium and magnesium.

SUMMARY OF THE INVENTION

In accordance with preferred embodiments of the invention a system and technique are provided to provide propped hydraulic fractures in a subterranean formation comprising: injecting a fracturing fluid into the subterranean formation at a pressure sufficient to initiate and propagate at least one hydraulic fracture wherein the fracturing fluid comprises a proppant; when the at least one hydraulic fracture has reached a target size, adding to the fracturing fluid a predetermined amount of a diverter material wherein the diverter material comprises between 10 to 30 weight percent of particles having a size larger than 2000 microns, between 1 and 15% by weight of particles between 1000 and 2000 microns, 10 to 40 percent by weight particles having a diameter in the range of 500 to 1000 microns, 40 to 70 percent by weight particles smaller than 500 microns, and comprising a material that degrades at conditions of the subterranean formation, the diverter material effective to essentially block flow of fracturing fluid into the at least one fracture; and continuing to inject fracturing fluid at a pressure effective to initiate at least one additional fracture within the subterranean formation.

The diverter material may be, for example polylactate, polyglycolate, or oil soluble resins. Slugs of diverter material may be injected may be injected between batches of injected fracturing fluid with each batch of diverter inhibiting flow of fracturing fluid into existing fractures. The greater the flow of fracturing fluid going into a particular fracture, the greater the amount of diverter initially entering the fracture will be, and thus rapidly growing fractures will be limited to essentially the size of the fracture at the time the diverter is injected. This allows subsequent fractures to become larger instead of dominate fractures containing the majority of the fracturing fluid and proppant.

In one embodiment of the invention, the size range of the diverter material is selected to enable bridging at the perforations and therefore blockage of fluid flow at the perforation. By essentially blocking flow of fracturing fluid at the perforation, the amount of diverter needed is predictable, and the amount of diverter is also considerably less than if the divertor were to be sized to block fluid flow in the fracture or within the proppant that has been placed within the fracture. Minimizing the amount of diverter material needed reduces costs of the diverter material, the costs and equipment needed to add the diverter material, and minimizes damage caused by the residual of the diverter material left in the formation after degradation of the diverter material.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed understanding of the invention, reference is made to the accompanying wherein:

FIG. 1 is a schematic drawing of a wellbore fractured according to the process of the present invention.

FIGS. 2 and 3 are plots of the amount of fracturing fluid forced into perforations in segments of wellbores with and without the use of the present invention.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

Referring now to FIG. 1, a wellbore 101 is shown penetrating a subterranean formation 102. The subterranean formation could be, for example, a hydrocarbon containing formation such as a light tight oil reservoir or a tight gas reservoir, or a formation into which carbon dioxide is to be sequestered. Generally formations having limited permeability require hydraulic fracturing such as provided by the present invention in order for fluids to be produced or injected into the formations. Low permeability formations could be formations having less than 10 milidarcy permeability. The wellbore could be vertical, horizontal, or deviated. In general, long horizontal wellbores are typically used for light tight oil and tight gas production so that many hydraulic fractures could be provided from each wellbore. The wellbore is provided by known drilling and completion methods. The wellbore could be an open hole completion within the formation to be produced, but to provide multiple fractures without having to move packers, wellbores that are cased with casing 103 and cemented into the formation with cement 104. The cement is generally pumped down the casing and followed by a wiper 105, which separates the cement from wellbore fluids behind the cement. The wiper may be stopped by a stopper ring 106 at the end of the casing. Known cement compositions and methods could be applied with the present invention.

A previously fractured segment of the wellbore 107 is show with three fractures 108 already provided into the subterranean formation. The casing is shown as having been provided with perforations 109 which penetrate the casing into the subterranean formation. A outboard packer 110 and an inboard packer 111, through which fracturing fluid may be provide via tubular 112, are provided to isolate a segment of the wellbore 114 from which additional fractures could now be provided. The tubular 112 is shown attached to both packers, and packers could be provided that could be released and moved via a separate hydraulic control line (not shown), or set to provide an isolated segment of the wellbore between the two packers. Only two segments of the wellbore containing fractures are shown, but it should be understood that typically many more segments are isolated and many more sets of fractures are provided. For example, a horizontal wellbore having a horizontal section 1828.8 meters long could be provided with hydraulic fractures every 15 to 200 meters to provide a wellbore having from 10 to 120 fractures. The fractures could be provided in sets of, for example, 2 to 10 fractures at a time. By providing multiple fractures at one time it is meant that the fractures are provided without changing the zone within the wellbore into which fracturing fluid is injected.

When packers are set, or a segment of a wellbore is otherwise isolated in preparation for providing hydraulic fractures, fracturing fluid 113 could be injected into the isolated segment of the wellbore 114, and through perforations 109, into the subterranean formation 102 at a pressure sufficiently high to initiate at least one new fracture.

Fracturing fluids 113 may be thickened to lower the rate at which proppants settle from the fluids, enabling the fluids to carry the proppants deeper into fractures. Thickeners may be viscosifying polymers such as a solvatable (or hydratable) polysaccharide, such as a galactomannan gum, a glycomannan gum, or a cellulose derivative. Examples of such polymers include guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl guar, hydroxyethyl cellulose, carboxymethyl-hydroxyethyl cellulose, hydroxypropyl cellulose, xanthan, polyacrylamides and other synthetic polymers. Of these, guar, hydroxypropyl guar and carboxymethlyhydroxyethyl guar are typically preferred based on commercial availability and cost/performance.

Alternatively, a fracturing fluid can be what is known as a slick water composition. A slick water comprises water and a low concentration of friction reducer along with a proppant such as sand. Typically slick water contains 99.5 percent by weight of water and sand, and 0.5 perceont by weight of additives, including, for example; a friction reducing polymer such as polyacrylamide; biocides such as bromine, methanol or naphthalene; surfactants such as butanol, or ethylene glycol monobutyl ether; and scale inhibitors such as hydrochlorinc acid or ethylene glycol. The slick water fracturing fluid does not include thickeners. High pumping rates are used to place the fracturing fluids within the formations before the proppants settle from the fluids. Slick water compositions are therefore more useful in shallow wells, wells with shorter horizontal laterals, or near the heal end of long horizontal wells. When slick water compositions can be utilized, they are generally preferred because thickeners increase hydraulic frictional pressure losses, and cause at least some formation damage.

Hydraulic fractures may be initiated with fluids not containing proppants, but proppants can then be added as the fractures propagate. Proppants may be sands or ceramic particles, polymer pellets, or glass particles. Proppants provide a more permeable filler for hydraulic fractures if they are provided with a relatively narrow range of sizes. Proppants such as those disclosed in U.S. Pat. Nos. 7,913,762, 7,836,952, or 8,327,940 could be used in the present invention. Proppants having relatively narrow size distributions provide high permeability propped fractures because void volumes are maximized Typical volume average size of useful proppants range from 100 to 2000 microns, and the distributions are preferably narrow.

Fracturing proppants size is specified as a mesh screen size that the sand pass through and a second mesh screen size which the proppant does not pass through. Porppant sizes useful in the present invention include, for example, 8/12, 10/20, 20/40, and 70/140. These screens correspond, respectively, to size range of 1.68 to 2.38, 0.84 to 2.00, 0.42 to 0.84, millimetres, and 105 to 210 microns. Most often, 20/40 sand is utilized.

Fracturing sand is also specified by sphericity and roundness by a chart devised by Krumbein and Sloss, and typically both sphericity and roundness are greater than 0.6 according to the chart of Krumbein and Sloss.

When a set of perforations within a wellbore is exposed to fluids at a pressure which exceeds the formation fracture initiation pressure, one or two dominate fractures will be initiated and will initially propagate. The majority of the injected proppant will flow into these dominate fractures until proppant injection is discontinued or no more proppant can be forced into the fracture. If proppant injection is continued after fractures are essentially filled with proppant, proppant may sand out in the wellbore. Generally, proppant injection is discontinued after a pre-determined amount of proppant has been injected to prevent proppant from filling the wellbore. The pre-determined amount of proppant could be estimated as the amount of proppant that could be placed in a fracture without the proppant “sanding out”, or becoming bridged within the fracture and blocking further movement of proppant into the fracture.

After injection of the proppant is discontinued, a flush of fracturing fluid that does not contain proppant will be injected to move proppant from within the wellbore into the fractures. In the present invention, a slug of a diverter material is pumped into the wellbore, preferably after the flush of proppant free fracturing fluid. The slug of diverter material comprises water or fracturing fluid, and diverter materials. The amount of pre-determined amount of proppant and fluid is based on fracturing job design that would give the target size of fractures.

Alternatively, the size of the area of the fracture may be inferred from micro seismic data, or it could be inferred merely from the volume of proppant containing fracturing fluid, or proppant, that has been injected.

Alternatively, the amount of fracturing fluid may be determined for the set of perforations to be fractured to optimize the fracturing based on normal considerations including the cost of the factures and the value of marginally larger fractures, and then this amount of fracturing fluid being injected in essentially equal portions, separated by slugs of fracturing fluid containing diverter material. The fracturing fluid may be divided into, for example, two, three, or four essentially equal portions, separated by one, two or three slugs of diverter materials.

Portions of fracturing fluids and proppants separated by the diversion slugs may be unequal based on fracturing design optimizations.

Before the slug of diverter is injected, the pressure at which fracturing fluid is being injected is typically stable. After the fluid containing the diverter has been injected, and the diverter material has traversed the tubular to the zone being fractured, the pressure at the wellhead will be seen to rise as fluid flow to existing fractures is blocked by the diverter material. Eventually, additional fractures open. Increases in pressure from fifty to three thousand pounds per square inch have been observed after injection of a slug of diverter. Because initial fractures increase the stress on the formation, each successive fracture will require increased pressure to initiate and propagate. Acceptable diverter material may be, for example, polylactate, polyglycolate, or oil soluble resins. Manufactures of such materials are capable of providing particles of such materials having specified size ranges and distributions, and which degrade under formation conditions at predictable rates.

Diverters of the present invention degrade at formation conditions over a time period that permits production of hydrocarbons from the wellbore within a reasonable amount of time. For example, the diverters may be designed to degrade at formation conditions between six and ninety days. By degrade, it is meant that the polymers lose more than half of their tensile strength. The degradation could also be accomplished by providing diverter material which is at least partially soluble in formation fluids, such as oil. The degradation could also be accomplished, accelerated, or triggered, by, for example, flushing an acidic component into the perforations. Alternatively a diverter material could be used that reacts with oxidizing agents and the degradation could be accomplished, accelerated, or triggered by flushing the perforations with an oxidizing agent.

The maximum size of the diverter, and the amount expected to block each perforation may be determined by, for example, labatory tests flowing diverter material through perforated rocks.

Diverter material could be added to the fracturing fluid as it is being injected, for example, by a screw pump into a mixing vessel or by direct manual feeding into a mixing vessel, and then being feed to fracturing fluid injection pumps. The diverter material may be added in a concentration that is great enough to be effective. If the concentration is not sufficient, the diverter material will not be sufficient to block flow into the fracture. To high of a concentration of diverter will be uneconomical, and difficult to add and mix into the fracturing fluid. Concentrations of diverter material between about 25 and about 200 grams per liter of fracturing fluid have been found to be effective and cost effective. Concentrations of between about 50 and 100 grams per liter may be acceptable.

To be an effective diverter material, the size distribution of the diverter material must be sufficiently broad. An acceptable broad particle size range would be a combination of particles wherein between 10 to 30 weight percent of particles have a size larger than 2000 microns, between 1 and 15% by weight of particles between 1000 and 2000 microns, 10 to 40 percent by weight particles having a diameter in the range of 500 to 1000 microns, 40 to 70 percent by weight particles smaller than 500 microns. The largest particles need to be large enough to bridge the perforations at the opening, and there need to be a sufficient amount of particles about one third of that size to bridge the openings between the largest particles, and then a sufficient amount of particles small enough to bridge the openings of between the smaller particles, and so on, until the particle size is below 500 micron. The different size range particles could be injected at one time, or could be injected sequentially with larger sizes injected first.

The size of the largest diverter particles, or for example, the diameter of which ten percent by volume of the material is greater than this diameter, depends upon where the diverter material is intended to block flow into the formation. If it is intended that flow into the formation is to be blocked at the face of proppant within the fracture, then this maximum diameter of diverter may be about one half of the average diameter of the proppant. If the diverter is intended to block flow within the fracture, then this maximum diameter of the diverter may be about one half of the width of the expected fracture opening. If the flow is intended to be blocked at the perforation itself, then the maximum diameter of the diverter material should be about half of the diameter of the perforation. Providing this size of diverter material minimizes the amount of diverter material needed to block the flow into the perforation. U.S. Pat. No. 7,004,255, for example, suggests combination of sizes of particles effective to block flows of fluids through proppant packed fractures. Bimodal distributions or trimodal distributions could be utilized, but a broad range of distributions is also effective.

The size distribution of the diverter material is preferably selected to block perforations. Blocking of the perforations can be accomplished with, for example, three to thirty kilograms of properly sized materials for each perforation. The amount of diverter material needed to block the perforations is also much more predictable than the amount of material needed to block the fracture or the proppant placed within the fracture because the dimensions of the actual perforation are known and are not significantly altered by the fracturing process.

The amount of diverter material may be, for example, between one and thirty kilograms per perforation to be blocked.

The present invention may be utilized to provide multiple fractures from within an isolated section of a wellbore, or could be utilized to provide fractures from a wellbore without isolating a section. For example, the whole segment of the wellbore to be provided with factures could be subjected to sequences of proppant containing fracturing fluids followed by slugs of diverter material repeatedly until fractures have been provided from each of the perforations in the wellbore without isolating sections of the wellbore.

The present invention could also be used with a well from which fractures had previously been provided. In this embodiment, proppant could be forced into existing fractures prior to could be subjected to injection of diverter material, to reopen or enlarge existing fractures. Alternatively, flow into existing fractures could be inhibited by injection of diverter material before new fractures are placed from the wellbore.

After a formation has been provided with hydraulic fractures according to the present invention, hydrocarbons may be produced from the formation by way of the hydraulic fractures. The hydrocarbons may be, for example, natural gas, crude oil, and/or light tight oil.

EXAMPLE 1

Diverter material was obtained from ICO Polymers North America, Inc, located in Akron, Ohio. The material was a polylactate biodegradable polymer with a size distribution of 1 to 2830 micron. In a horizontal well bore that had been drilled, cased, and all but the last three stages were fraced by normal procedures. The last three stages, at the heel end of the wellbore, were combined into one stage to test the effectiveness of one embodiment of the present invention. This section of the wellbore was about eight hundred feet long. This segment was peforated with nine clusters of perforations, the clusters being separated by about 84 feet. The amount of fracturing fluid and proppant used was the normal amount for three stages, or three times the amount used for the previous individual stages. The total amount of proppant pumped was about 900,000 pounds. The proppant and fluid was injected in three roughly equal batches, each batch separated by a slug of diverter material in fluid. For each batch of diverter, about 450 pounds of diverter material was added to 600 gallons of liner gel solution. After the first batch of proppant was pumped, and the first batch of diverter, the diverter caused the back pressure to build by about 700 psi. After the first slug of diverter was pumped, a second batch of proppant was pumped. The second batch of proppant required about two hundred psi more pressure than the first. This indicates that new perforations were opening. After the second batch of proppant was pumped, the second batch of diverter material was pumped. Again, about 450 pounds of diverter were pumped in about 600 gallons of liner gel fluid. This time the pressure built as the diverter was being pumped by about 400 psi. A third and final batch of proppant was then pumped, and again the fracturing pressures increased by about another two hundred psi, indicating that the proppant was entering new fractures.

EXAMPLE 2

For this example, the diverter material was commercially available material, Biovert, from Halliburton Energy Services, Inc., of Houston, Tex. The well was a well equipped with a fiber optic sensor capable of measuring a complete temperature and acoustic profile within the well. With the complete acoustic and temperature profile, as a function of time, the distribution of fracturing fluid going into different perforations within a cluster may be calculated. Typically, without the present invention, it is observed that when a cluster of six perforations are fractured, there will be one to three dominate fractures, with three to five fractures receiving considerably less proppant. Therefore, normal procedures would be to not attempt to fracture more than three clusters per stage. This results in more effective fractures within the wellbore, and more predictable placement of fractures, but increases completion costs. To demonstrate the effectiveness of one embodiment of the present invention, the proppant was pumped in two batches, separated by a batch of fluids containing BioVert material. FIG. 1 shows the relative distribution of proppant material for the two batches of proppant for each of six clusters of perforations. The proppant pumped first went mostly into the first three sets of perforations. It can be seen that over ninety percent of the proppant went into these perforations. After the injection of the diverter material, much more of the second batch of proppant went into the other three perforations, with about fifty percent going into the fourth perforation and less than ten percent going into each of the first three. Although in this example, sufficient proppant was not forced into the fifth and sixth perforations, the distribution of proppant was significantly improved by the slug of diverter material.

EXAMPLE 3

Another test to determine if open clusters could be blocked to divert fracture fluids into unopened clusters of perforations in a horizontal well in the Eagle Ford formation. The diverter used was commercially available BioVert from Halliburton. Referring now to FIG. 2, the x-axis is the number for clusters in one stage. The Y axis is the percentage of fracturing fluid and slurry taken by each clusters. During the job, the total fluid and slurry volume were divided into two portions. The first portion was pumped as a regular fracturing procedure. The solid line indicates the percentage of fluid and slurry taken by each cluster during the first portion of the treatment calculated from fiber optic temperature sensor data. The results show that during the first portion of the treatment, there are four clusters taking fluid and slurry, one cluster was taking more than the others. Two clusters did not take any fluids. A diverter slug was pumped after the first portion of treatment. The second portion of the treatment was then pumped. The dotted line shows the percentage of fluid and slurry taken by each cluster during pumping the second portion. The results show that the second portion of the treatment opened cluster 6 and improved the fracturing efficiency. 

We claim:
 1. A method to provide propped hydraulic fractures in a subterranean formation comprising: injecting a fracturing fluid into the subterranean formation at a pressure sufficient to initiate and propagate at least one hydraulic fracture wherein the fracturing fluid comprises a proppant; adding to the fracturing fluid, when the at least one hydraulic fracture has reached a target size, a predetermined amount of a diverter material wherein the diverter material comprises between 10 to 30 weight percent of particles having a size larger than 2000 microns, between 1 and 15% by weight of particles between 1000 and 2000 microns, 10 to 40 percent by weight particles having a diameter in the range of 500 to 1000 microns, 40 to 70 percent by weight particles smaller than 500 microns, and comprising a material that degrades at conditions of the subterranean formation, the diverter material effective to essentially block flow of fracturing fluid into the at least one fracture; and continuing to inject fracturing fluid at a pressure effective to initiate at least one additional fracture within the subterranean formation.
 2. The method of claim 1 further comprising the step of providing a wellbore withink the subterranean formation and providing a casing within the wellbore
 3. The method of claim 2 further comprising perforating the casing within the subterranean formation wherein the diverter material is sized to bridge the perforations
 4. The method of claim 3 wherein the diverter material is sized to bridge the perforations.
 5. The method of claim 1 wherein the time when the fracture has reached the target size is determined by the volume of fracturing fluid injected.
 6. The method of claim 1 wherein the time when the fracture has reached the target size is determined by the rate at which fracture fluid can be injected into the formation at a pressure that is less than the fracture initiation pressure.
 7. The method of claim 1 wherein the time when the fracture has reached the target size is determined by microseismic data.
 8. The method of claim 1 wherein the material that degrades at conditions of the subterranean formation comprises polylactate,
 9. The method of claim 1 wherein the material that degrades at conditions of the subterranean formation comprises polyglycolate.
 10. The method of claim 1 wherein the material that degrades at conditions of the subterranean formation comprises oil soluble resins.
 11. The method of claim 1 wherein the material that degrades at ambient conditions of the subterranean formation degrades within a time period in the range of six hours to ninety days.
 12. The method of claim 1 wherein the steps are repeated a plurality of times.
 13. The method of claim 1 further comprising the step of producing hydrocarbons from the subterranean formation through the fractures.
 14. The method of claim 1 wherein the wellbore is essentially horizontal for at least a portion of the wellbore within the subterranean formation.
 15. The method of claim 1 wherein the wellbore is slanted from horizontal for at least a portion of the wellbore within the subterranean formation.
 16. The method of claim 1 wherein the wellbore is essentially vertical for at least a portion of the wellbore within the subterranean formation.
 17. The method of claim 1 wherein the concentration of diverter in the fracturing fluid is between 25 and 200 grams per liter.
 18. A method to provide propped hydraulic fractures in a subterranean formation comprising: injecting a fracturing fluid into the subterranean formation at a pressure sufficient to initiate and propagate at least one hydraulic fracture wherein the fracturing fluid comprises a proppant; when the at least one hydraulic fracture has reached a target size, adding to the fracturing fluid a predetermined amount of a diverter material wherein the diverter material comprises between 10 to 30 weight percent of particles having a size larger than 2000 microns, between 1 and 15% by weight of particles between 1000 and 2000 microns, 10 to 40 percent by weight particles having a diameter in the range of 500 to 1000 microns, 40 to 70 percent by weight particles smaller than 500 microns, and comprising a material that degrades at ambient conditions of the subterranean formation, the diverter material effective to essentially block flow of fracturing fluid into the at least one fracture; and continuing to inject fracturing fluid at a pressure effective to initiate at least one additional fracture from the wellbore within the subterranean formation.
 19. A method to provide acid or reactive chemical etched fractures in a subterranean formation comprising: injecting a reactive chemical into the subterranean formation at a pressure sufficient to initiate and propagate at least one hydraulic fracture wherein the fracturing fluid comprises a reactive chemical that can etch the fracture surface; when the at least one hydraulic fracture has reached a target size, adding to the fracturing fluid a predetermined amount of a diverter material wherein the diverter material comprises between 10 to 30 weight percent of particles having a size larger than 2000 microns, between 1 and 15% by weight of particles between 1000 and 2000 microns, 10 to 40 percent by weight particles having a diameter in the range of 500 to 1000 microns, 40 to 70 percent by weight particles smaller than 500 microns, and comprising a material that degrades at ambient conditions of the subterranean formation, the diverter material effective to essentially block flow of fracturing fluid into the at least one fracture; and continuing to inject fracturing fluid at a pressure effective to initiate at least one additional fracture from the wellbore within the subterranean formation. 